Methods of using polymer-coated particulates

ABSTRACT

Methods are provided including a method comprising: providing a treatment fluid comprising particulates at least partially coated with a polymer, wherein the polymer is deposited on the particulates by at least partially coating the particulates with a polymer solution comprising the polymer and a solvent and then exposing the particulates to an aqueous medium such that the solvent substantially dissociates from the polymer solution and such that the polymer substantially remains on the particulates; introducing the treatment fluid into a portion of a subterranean formation; and, depositing at least a portion of the particulates in the portion of the subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present invention is related to U.S. application Ser. No. 11/076,005entitled “Polymer-Coated Particulates” filed on the same date herewith,which is assigned to the assignee of the present invention, the entiredisclosure of which is incorporated herein by reference.

BACKGROUND OF THE INVENTION

The present invention relates to methods of using polymer-coatedparticulates in subterranean operations such as gravel packing,frac-packing, and hydraulic fracturing.

Hydrocarbon-producing wells are often stimulated by hydraulic fracturingtreatments. In hydraulic fracturing treatments, a viscous fracturingfluid is pumped into a producing zone at a rate and pressure such thatthe subterranean formation breaks down and one or more fractures areformed or extended in the zone. Particulate solids, such as graded sand,which are often referred to as “proppant” may be suspended in a portionof the fracturing fluid and then deposited in the fractures when thefracturing fluid is converted to a thin fluid to be returned to thesurface. These particulates serve, among other things, to prevent thefractures from fully closing so that conductive channels are formedthrough which produced hydrocarbons may flow.

Hydrocarbon-producing wells may also undergo gravel packing treatmentsto, inter alia, reduce the migration of unconsolidated formationparticulates into the well bore. In gravel packing operations,particulates, often referred to in the art as gravel, are suspended in atreatment fluid, which may be viscosified, and the treatment fluid ispumped into a well bore in which the gravel pack is to be placed. As theparticulates are placed in or near the zone, the treatment fluid eitheris returned to the surface or leaks off into the subterranean zone. Theresultant gravel pack acts as a filter to prevent the production of theformation solids with the produced fluids. Traditional gravel packoperations involve placing a gravel pack screen in the well bore andthen packing the surrounding annulus between the screen and the wellbore with gravel. The gravel pack screen is generally a filter assemblyused to support and retain the gravel placed during the gravel packoperation. A wide range of sizes and screen configurations is availableto suit the characteristics of a well bore, the production fluid, andany particulates in the subterranean formation.

In some situations, hydraulic fracturing and gravel packing operationsmay be combined into a single treatment. Such treatments are oftenreferred to as “frac pack” operations. In some cases, the treatments aregenerally completed with a gravel pack screen assembly in place with thehydraulic fracturing treatment being pumped through the annular spacebetween the casing and screen. In this situation, the hydraulicfracturing treatment ends in a screen-out condition, creating an annulargravel pack between the screen and casing. In other cases, thefracturing treatment may be performed prior to installing the screen andplacing a gravel pack.

Particulates (such as proppant or gravel) used in subterraneanoperations are often coated with a resinous or polymeric material tofacilitate consolidation of the particulates. In some cases, the coatingmay also be used to strengthen low-quality particulates. Creating suchcoated particulates generally involves using solvent methods that maypose health or environments risks. Moreover, many particulate coatingtechnologies, such as epoxy resin solvent systems, are relativelyexpensive. Thus, between the potential environmental and health hazardsposed by many of the particulate coating technologies and the exorbitantcosts of some, known coating techniques are less than ideal forwidespread use in subterranean operations.

SUMMARY OF THE INVENTION

The present invention relates to methods of using polymer-coatedparticulates in subterranean operations such as gravel packing,frac-packing, and hydraulic fracturing.

One embodiment of the present invention provides methods for depositinga polymer on particulates suitable for use in a subterranean operationcomprising providing particulates and a polymer solution comprising apolymer and a polar, aprotic solvent; at least partially coating theparticulates with the polymer solution to create coated particulates;and, exposing the coated particulates to an aqueous medium such that thesolvent substantially dissociates from the polymer solution and suchthat the polymer substantially remains on the particulates.

Another embodiment of the present invention provides methods of treatinga subterranean formation comprising providing a treatment fluidcomprising particulates at least partially coated with a polymer,wherein the polymer is deposited on the particulates by at leastpartially coating the particulates with a polymer solution comprisingthe polymer and a solvent and then exposing the particulates to anaqueous medium such that the solvent substantially dissociates from thepolymer solution and such that the polymer substantially remains on theparticulates; introducing the treatment fluid into a portion of asubterranean formation; and, depositing at least a portion of theparticulates in the portion of the subterranean formation.

Yet another embodiment of the present invention provides methods ofcreating a propped fracture in a portion of a subterranean formationcomprising hydraulically fracturing a portion of a subterraneanformation to create or enhance at lease one fracture therein; providinga fracturing fluid comprising particulates at least partially coatedwith a polymer, wherein the polymer is deposited on the particulates byat least partially coating the particulates with a polymer solutioncomprising the polymer and a solvent and then exposing the particulatesto an aqueous medium such that the solvent substantially dissociatesfrom the polymer solution and such that the polymer substantiallyremains on the particulates; placing the fracturing fluid into the atleast one fracture; and, depositing at least a portion of theparticulates in the at least one fracture.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to methods of using polymer-coatedparticulates in subterranean operations such as gravel packing,frac-packing, and hydraulic fracturing.

In accordance with the teachings of the present invention, particulatesat least partially coated with a polymer may be used to facilitate theconsolidation of the particulates into a permeable mass havingcompressive and tensile strength. Generally, the polymer is depositedonto the particulates by at least partially coating the particulateswith a polymer solution comprising a polymer and a solvent, and thenexposing the particulates to an aqueous medium such that the solventsubstantially dissociates from the polymer solution, leaving behind thepolymer on the particulates. Suitable polymers are substantially solubleor miscible in the chosen solvent and are not substantially soluble ormiscible in water. Suitable solvents are substantially soluble ormiscible in water. In some embodiments of the present invention,particulates may be coated with the polymer in an amount of from about0.1% to about 25% by weight of the particulates. In other embodiments ofthe present invention, particulates may be coated with the polymer in anamount of from about 1% to about 5% by weight of the particulates. Inparticular embodiments, the present invention provides a low-cost andenvironmentally-sound method of coating particulates with a polymer thatmay improve the quality of low-quality particulates and/or may improvethe resiliency and crush resistance of a resulting particulate pack.

Particulates suitable for use in the present invention may be comprisedof any material suitable for use in subterranean operations. Suitableparticulate materials include, but are not limited to, sand; bauxite;ceramic materials; glass materials; polymer materials;polytetrafluoroethylene (TEFLON®) materials; nut shell pieces; seedshell pieces; cured resinous particulates comprising nut shell pieces;cured resinous particulates comprising seed shell pieces; fruit pitpieces; cured resinous particulates comprising fruit pit pieces; wood;composite particulates and combinations thereof. Composite particulatesmay also be suitable, suitable composite materials may comprise a binderand a filler material wherein suitable filler materials include silica,alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide,meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash,hollow glass microspheres, solid glass, and combinations thereof.Typically, the coated particulates have a size in the range of fromabout 2 to about 400 mesh, U.S. Sieve Series. In particular embodiments,preferred coated particles size distribution ranges are one or more of6/12 mesh, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70mesh. It should be understood that the term “particulate,” as used inthis disclosure, includes all known shapes of materials includingsubstantially spherical materials, fibrous materials, polygonalmaterials (such as cubic materials) and mixtures thereof. Moreover,fibrous materials that may or may not be used to bear the pressure of aclosed fracture, are often included in proppant and gravel treatments.It should be understood that the term “proppant,” as used in thisdisclosure, includes all known shapes of materials includingsubstantially spherical materials, fibrous materials, polygonalmaterials (such as cubic materials) and mixtures thereof.

Some embodiments of the present invention are particularly well-suitedfor use with low-quality particulates. By their nature, low-qualityparticulates are often plagued by fines and/or breakage, making theiruse with a consolidating or strengthening polymeric coatingadvantageous. As used herein, the term “low-quality particulates” refersto particulates that do not meet at least one of the standards forsphericity, roundness, size, turbidity, acid solubility, percentage offines, or crush resistance as recited in American Petroleum InstituteRecommended Practices (API RP) standard numbers 56 and 58 for proppantand gravel respectively.

The API RP's describe the minimum standard for sphericity as at least0.6 and for roundness as at least 0.6. As used herein, the terms“sphericity” and “roundness” are defined as described in the API RP'sand can be determined using the procedures set forth in the API RP's.

API RP 56 also sets forth some commonly recognized proppant sizes as6/12, 8/16, 12/20, 20/40, 30/50, 40/70, and 70/140. Similarly, API RP 58also sets forth some commonly recognized gravel sizes as 8/16, 12/20,16/30, 20/40, 30/50, and 40/60. The API RP's further note that a minimumpercentage of particulates that should fall between designated sandsizes and that not more than 0.1 weight % of the particulates should belarger than the larger sand size and not more than a maximum percentage(1 weight % in API RP 56 and 2 weight % in API RP 58) should be smallerthan the small sand size. Thus, for 20/40 proppant, no more than 0.1weight % should be larger than 20 U.S. Mesh and no more than 1 weight %smaller than 40 U.S. Mesh.

API RP's 56 and 58 describe the minimum standard for proppant and gravelturbidity as 250 FTU or less. API RP 56 describes the minimum standardfor acid solubility of proppant as no more than 2 weight % loss whentested according to API RP 56 procedures for proppant sized between 6/12Mesh and 30/50 Mesh, U.S. Sieve Series and as no more than 3 weight %loss when tested according to API RP 56 procedures for proppant sizedbetween 40/70 Mesh and 70/140 Mesh, U.S. Sieve Series. API RP 58describes the minimum standard for acid solubility of gravel as no morethan 1 weight % loss when tested according to API RP 58 procedures. APIRP 56 describes the minimum standard for crush resistance of proppant asproducing not more than the suggested maximum fines as set forth inTable 1, below, for the size being tested:

TABLE 1 Suggested Maximum Fines for Proppant Subjected to CrushingStrength Mesh Size Stress on (U.S. Sieve Crushing Force Proppant MaximumFines Series) (lbs) (psi) (% by weight)  6/12 6,283 2,000 20  8/16 6,2832,000 18 12/20 9,425 3,000 16 16/30 9,425 3,000 14 20/40 12,566 4,000 1430/50 12,566 4,000 10 40/70 15,708 5,000 8  70/140 15,708 5,000 6Similarly, API RP 58 describes the minimum standard for crush resistanceof gravel as producing not more than the suggested maximum fines as setforth in Table 2, below, for the size being tested:

TABLE 2 Suggested Maximum Fines for Gravel Subjected to CrushingStrength Mesh Size Stress on (U.S. Sieve Crushing Force Gravel MaximumFines Series) (lbs) (psi) (% by weight)  8/16 6,283 2,000 8 12/20 6,2832,000 4 16/30 6,283 2,000 2 20/40 6,283 2,000 2 30/50 6,283 2,000 240/60 6,283 2,000 2

As mentioned above, the particulates of the present invention are atleast partially coated with a polymer solution comprising a polymer anda solvent. Generally, any polymer that has a thermal and chemicalresistance suitable for use in a down hole environment and that may aidparticulates in forming a permeable mass having at least some cohesivestrength may be used in accordance with the teachings of the presentinvention. Suitable polymers are not readily soluble in water and may bemade into a solution in a suitable solvent (such as propylene carbonate)and then may be made to precipitate out of the solvent when placed in anaqueous fluid (such as a fracturing fluid). By way of example, asolution can be made by dissolving acrylic fibers (containing at leastabout 85% acrylonitrile units) into N,N-dimethylformamide (“DMF”) toform a 20 weight percent solution of acrylic in DMF; when exposed towater, acrylic polymer beads precipitate out of the DMF solution andinto the water.

Some suitable polymers include, but are not limited to, acrylic polymerssuch as acrylonitrile polymers, acrylonitrile copolymers, and mixturesthereof. Some preferred polymers include homopolymers and copolymers ofpolyacrylonitrile (including copolymers of acrylonitrile and methylacrylate, methyl methacrylate, vinyl chloride, styrene and butadiene),polyacylates, polymethacrylates, poly(vinyl alcohol) and its derivates,and mixtures thereof. As used herein the term “acrylic” polymers refersto any synthetic polymer composed of at least 85% by weight ofacrylonitrile units (the Federal Trade Commission definition). Thus, thedefinition of the term may include homopolymers of polyacrylonitrile andcopolymers containing polyacrylonitrile. Usually they are copolymers ofacrylonitrile and one or more of the following: methyl acrylate, methylmethacrylate, vinyl chloride, styrene, butadiene. However, polymers thatdo not meet the definition of an acrylic polymer (such as those havingless than 85% acrylonitrile) may also be suitable. For instance, Example3 uses poly(acrylonitrile-co-butadiene-co-styrene) that containsapproximately 25 wt % acrylonitrile. Furthermore, anyone skilled in theart can select a wide variety of suitable polymers (includingnon-acrylic polymers) and solvents from numerous sources. For example,using published references such as the Polymer Handbook (J. Brandrup J.and E. H. Immergut, John Wiley & Sons, New York, 1989) one could find apolymer suitable for their application with example solvents. Forexample, from the reference previously cited it can be found thatpoly(methyl methacrylate) and poly(vinyl acetate) are soluble in acetonewhich is a water soluble/miscible solvent. The polymer may be present inthe polymer solution in an amount from about 5 to about 95% by weight ofthe polymer solution. Typically, the polymer is present in the polymersolution in an amount of from about 5% to about 95% by weight of thepolymer solution. In some embodiments the polymer is present in thepolymer solution in an amount of from about 25% to about 75% by weightof the polymer solution.

The solvent of the present invention generally comprise polar, aproticsolvents. In particular embodiments, the solvent is non-aromatic.Suitable such solvents include, but are not limited to,N,N-dimethylformamide (“DMF”); acetone; tetrahydrofuran (“THF”);1,4-dioxane; dimethylsulfoxide (“DMSO”); tetramethylenesulfone(sulfolane); acetonitrile; hexamethylphosphoramide (“HMPA”);1,3-methyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone (“DMPU”); propylenecarbonate, ethylene carbonate and mixtures thereof. In particularembodiments of the present invention, propylene carbonate is used as thesolvent due to the fact that it is inexpensive, is relativelyenvironmentally sound, and has a high boiling point.

After at least partially coating the particulates with the polymersolution, the polymer-coated particulates are exposed to an aqueoustreatment fluid or some other source of water. Suitable aqueous mediainclude fresh water, salt water, brine, or any other aqueous liquid thatdoes not adversely react with the polymer or solvent of the presentinvention. In particular embodiments, the fracturing fluid theparticulates are to be suspended in is the aqueous medium. Due to thehighly water-soluble nature of the solvent, the solvent substantially,and oftentimes rapidly, dissociates from the polymer solution uponexposure to the aqueous medium Upon dissociation, the solvent enters theaqueous medium, leaving behind the polymer on the surface of theparticulates. So deposited, the polymer typically is present on theresulting polymer-coated particulates in an amount of from about 0.01%to about 10% by weight of the particulates, preferably from about 1% toabout 3% by weight of the particulates.

In particular embodiments of the present invention, the particulates maybe coated with the polymer solution and introduced into the treatmentfluid, which acts as the aqueous medium, directly prior to beingintroduced into a subterranean formation in an on-the-fly treatment. Asused herein, the term “on-the-fly” is used to mean that a flowing streamis continuously introduced into another flowing stream so that thestreams are combined and mixed while continuing to flow as a singlestream as part of an on-going treatment. For instance, thepolymer-coated particulates may be mixed with an aqueous liquid (such asa treatment fluid) on-the-fly to form a treatment slurry. Such mixingcan also be described as “real-time” mixing. As is well understood bythose skilled in the art such mixing may also be accomplished by batchor partial batch mixing. One benefit of on-the-fly mixing over batch orpartial batch mixing, however, involves reducing waste by having theability to rapidly shut down the mixing of the components on-the-fly.

Generally, any treatment fluid suitable for a subterranean operation maybe used in accordance with the teachings of the present invention,including aqueous gels, viscoelastic surfactant gels, foamed gels andemulsions. Suitable aqueous gels are generally comprised of water andone or more gelling agents. Suitable emulsions can be comprised of twoimmiscible liquids such as an aqueous liquid or gelled liquid and ahydrocarbon. Foams can be created by the addition of a gas, such ascarbon dioxide or nitrogen. In exemplary embodiments of the presentinvention, the fracturing fluids are aqueous gels comprised of water, agelling agent for gelling the water and increasing its viscosity, and,optionally, a crosslinking agent for crosslinking the gel and furtherincreasing the viscosity of the fluid. The increased viscosity of thegelled, or gelled and cross-linked, treatment fluid, inter alia, reducesfluid loss and allows the fracturing fluid to transport significantquantities of suspended particulates. The water used to form thetreatment fluid may be fresh water, salt water, brine, sea water, or anyother aqueous liquid that does not adversely react with the othercomponents. The density of the water can be increased to provideadditional particle transport and suspension in the present invention.

A variety of gelling agents may be used, including hydratable polymersthat contain one or more functional groups such as hydroxyl, carboxyl,sulfate, sulfonate, amino, or amide groups. Suitable gelling typicallycomprise polymers, synthetic polymers, or a combination thereof. Avariety of gelling agents can be used in conjunction with the methodsand compositions of the present invention, including, but not limitedto, hydratable polymers that contain one or more functional groups suchas hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylicacids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide. Incertain exemplary embodiments, the gelling agents may be polymerscomprising polysaccharides, and derivatives thereof that contain one ormore of these monosaccharide units: galactose, mannose, glucoside,glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosylsulfate. Examples of suitable polymers include, but are not limited to,guar gum and derivatives thereof, such as hydroxypropyl guar andcarboxymethylhydroxypropyl guar, and cellulose derivatives, such ashydroxyethyl cellulose. Additionally, synthetic polymers and copolymersthat contain the above-mentioned functional groups may be used. Examplesof such synthetic polymers include, but are not limited to,polyacrylate, polymethacrylate, polyacrylamide, polyvinyl alcohol, andpolyvinylpyrrolidone. In other exemplary embodiments, the gelling agentmolecule may be depolymerized. The term “depolymerized,” as used herein,generally refers to a decrease in the molecular weight of the gellingagent molecule. Depolymerized gelling agent molecules are described inU.S. Pat. No. 6,488,091 issued Dec. 3, 2002 to Weaver, et al., therelevant disclosure of which is incorporated herein by reference.Suitable gelling agents generally are present in the viscosifiedtreatment fluids of the present invention in an amount in the range offrom about 0.1% to about 5% by weight of the water therein. In certainexemplary embodiments, the gelling agents are present in the viscosifiedtreatment fluids of the present invention in an amount in the range offrom about 0.01% to about 2% by weight of the water therein.

Crosslinking agents may be used to crosslink gelling agent molecules toform crosslinked gelling agents. Crosslinkers typically comprise atleast one metal ion that is capable of crosslinking molecules. Examplesof suitable crosslinkers include, but are not limited to, zirconiumcompounds (such as, for example, zirconium lactate, zirconium lactatetriethanolamine, zirconium acetylacetonate, zirconium citrate, andzirconium diisopropylamine lactate); titanium compounds (such as, forexample, titanium lactate, titanium citrate, titanium ammonium lactate,titanium triethanolamine, and titanium acetylacetonate); aluminumcompounds (such as, for example, aluminum lactate or aluminum citrate);antimony compounds; chromium compounds; iron compounds; coppercompounds; zinc compounds; or a combination thereof. An example of asuitable commercially available zirconium-based crosslinker is “CL-24 ”available from Halliburton Energy Services, Inc., Duncan, Okla. Anexample of a suitable commercially available titanium-based crosslinkeris “CL-39” available from Halliburton Energy Services, Inc., DuncanOkla. Suitable crosslinkers generally are present in the viscosifiedtreatment fluids of the present invention in an amount sufficient toprovide, inter alia, the desired degree of crosslinking between gellingagent molecules. In certain exemplary embodiments of the presentinvention, the crosslinkers may be present in an amount in the rangefrom about 0.001% to about 10% by weight of the water in the fracturingfluid. In certain exemplary embodiments of the present invention, thecrosslinkers may be present in the viscosified treatment fluids of thepresent invention in an amount in the range from about 0.01% to about 1%by weight of the water therein. Individuals skilled in the art, with thebenefit of this disclosure, will recognize the exact type and amount ofcrosslinker to use depending on factors such as the specific gellingagent, desired viscosity, and formation conditions.

The gelled or gelled and cross-linked treatment fluids may also includeinternal delayed gel breakers such as enzyme, oxidizing, acid buffer, ortemperature-activated gel breakers. The gel breakers cause the viscoustreatment fluids to revert to thin fluids that can be produced back tothe surface after they have been used to place particulates insubterranean fractures. The gel breaker used is typically present in thetreatment fluid in an amount in the range of from about 0.5% to about10% by weight of the gelling agent. The treatment fluids may alsoinclude one or more of a variety of well-known additives, such as gelstabilizers, fluid loss control additives, clay stabilizers,bactericides, and the like.

In some embodiments of the present invention, the particulates may becoated with the polymer solution and exposed to an aqueous medium wellin advance of being introduced into a subterranean formation, creatingpolymer-coated particulates that may be used at some time in the future.

By coating with particulates with the polymer of the present invention,the quality of the particulates may be improved, particularly inembodiments employing low-quality particulates. In addition to improvinglow-quality particulates to make it suitable for a fracturingapplication, particular embodiments may improve the resiliency of aparticulate pack comprising the polymer-coated particulates of thepresent invention. In particular embodiments, the resulting particulatesmay have improved crush resistance, may be less susceptible to pointloading, and/or may be better able to withstand stress cycling. Thepolymer coating of the present invention may also reduce finesgeneration by entraining fines released by the particulates, preventingthe fines negatively impacting the production potential of the well.

In particular embodiments of the present invention, the polymer-coatedparticulates may also be at least partially coated with a partitioningagent. By coating a partitioning agent onto particulates that has beencoated with the polymer, the methods of the present invention arecapable of temporarily diminishing the “tackiness” of the treatedparticulates, thus preventing or minimizing the agglomeration of theparticulates and the spreading of the polymer onto equipment surfacesbefore introduction into a subterranean formation. Because of this, theuse of a partitioning agent may be particularly useful where thepolymer-coated particulates will not be directly introduced into asubterranean formation (i.e., in non-“on-the-fly” operations).Partitioning agents suitable for use in the present invention are thosesubstances that will dissipate once the particulates are introduced to atreatment fluid, such as a fracturing or gravel packing fluid. Moreover,partitioning agents suitable for use in the present invention should notinterfere with the polymer coated onto the particulate when it is used,and should not interfere with the treatment fluid. In particularembodiments, the partitioning agent is coated onto the polymer-coatedparticulates in an amount of from about 1% to about 20% by weight of thepolymer-coated particulates. In particular embodiments, substantiallythe entire surface of the polymer coating is coated with partitioningagent.

Partitioning agents suitable for use in the present invention are thosematerials that are capable of coating onto the polymer coating of theparticulates and reducing the tacky character of the polymer coating.Suitable partitioning agents may be substances that will quicklydissipate in the presence of the aqueous liquid. Examples of suitablepartitioning agents that will dissolve quickly in an aqueous liquidinclude salts (such as rock salt, fine salt, KCl, and other solid saltsknown in the art), barium sulfate, benzoic acid, polyvinyl alcohol,sodium carbonate, sodium bicarbonate, and mixtures thereof. Thepartitioning agent also may be a substance that dissipates more slowlyin the presence of the aqueous liquid. Partitioning agents that dissolvemore slowly allow more time to place the coated particulates. Examplesof suitable partitioning agents that will dissolve more slowly in anaqueous liquid include calcium oxide, degradable polymers, such aspolysaccharides; chitins; chitosans; proteins; aliphatic polyesters;poly(lactides); poly(glycolides); poly(ε-caprolactones);poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates;poly(orthoesters); poly(amino acids); poly(ethylene oxides); andpoly(phosphazenes); and mixtures thereof.

To facilitate a better understanding of the present invention, thefollowing examples of preferred embodiments are given. In no way shouldthe following examples be read to limit or define the scope of theinvention.

EXAMPLES Example 1

Acrylic fibers (containing at least about 85% acrylonitrile units weredissolved into N,N-dimethylformamide (“DMF”) to form a 20 weight percentsolution of acrylic in DMF. The solution was then dropped into water andacrylic polymer beads precipitated out of the DMF and into the water.

Example 2

Acrylic fibers (containing at least about 85% acrylonitrile units weredissolved into propylene carbonate to form a 20 weight percent solutionof acrylic in propylene carbonate. Ten grams of the solution of acrylicin propylene carbonate were then coated into 100 grams of 20/40 Bradysand. The coated sand was then placed into water and propylene carbonatecame out of the solution and the acrylic polymer was observed to depositonto the surface of the sand particulate leaving an about 2% by weightcoating on the polymer.

Example 3

Ten grams of poly(acrylonitrile-co-butadiene-co-styrene) (comprisingabout 25 weight % acrylonitrile) was dissolved in 90 grams of propylenecarbonate at about 110-120° F. Three milliliters of the resulting liquidpolymer solution was then coated onto about 100 grams of 20/40 Bradysand. The coated sand was then slurried into about 200 ml of an aqueousxanthan gel liquid and the poly(acrylonitrile-co-butadiene-co-styrene)polymer came out of the propylene carbonate and was deposited onto thesand when the solvent went into the aqueous xanthan gel liquid.’

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Whilenumerous changes may be made by those skilled in the art, such changesare encompassed within the spirit of this invention as defined by theappended claims.

1. A method for depositing a polymer on particulates suitable for use ina subterranean operation comprising: providing particulates and apolymer solution comprising a polymer and a polar, aprotic solvent; atleast partially coating the particulates with the polymer solution tocreate coated particulates; and, exposing the coated particulates to anaqueous medium such that the solvent substantially dissociates from thepolymer solution and such that the polymer substantially remains on theparticulates.
 2. The method of claim 1 wherein the polymer comprises atleast one polymer selected from the group consisting of:polyacrylonitrile, a copolymer of acrylonitrile and methyl acrylate, acopolymer of acrylonitrile and methyl methacrylate, a copolymer ofacrylonitrile and vinyl chloride, a copolymer of acrylonitrile andstyrene, a copolymer of acrylonitrile and butadiene, a polyacylate, apolymethacrylate, a poly(vinyl alcohol), and a derivative of poly(vinylalcohol).
 3. The method of claim 1 wherein the solvent comprises atleast one solvent selected from the group consisting of:N,N-dimethylformamide; acetone; tetrahydrofuran; 1,4-dioxane;dimethylsulfoxide; tetramethylenesulfone; acetonitrile;hexamethylphosphoramide;1,3-methyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; propylene carbonate,and ethylene carbonate.
 4. The method of claim 1 wherein the polymer ispresent in the polymer solution in an amount of from about 5% to about95% by weight of the polymer solution.
 5. The method of claim 1 whereinthe particulates comprise low-quality particulates.
 6. The method ofclaim 1 wherein the particulates are coated with the polymer in anamount of from about 0.1% to about 25% by weight of the particulates. 7.The method of claim 1 wherein the aqueous medium comprises an aqueousfracturing fluid.
 8. The method of claim 7 wherein the particulates arecoated with the partitioning agent in an amount of from about 1% toabout 20% by weight of the particulates and wherein the partitioningagent comprises at least one partitioning agent selected from the groupconsisting of: a salt, barium sulfate, benzoic acid, polyvinyl alcohol,sodium carbonate, sodium bicarbonate, a chitin, chitosan, protein,aliphatic polyester, poly(lactide), poly(glycolide),poly(ε-caprolactone), poly(hydroxybutyrate), poly(anhydride), aliphaticpolycarbonate, poly(orthoester), poly(amino acid), poly(ethylene oxide),poly(phosphazene), degradable polymer, calcium oxide, a wax, gilsonite,sulfonated asphalt, naphthalenesulfonate, and an oil-soluble resin. 9.The method of claim 1 further comprising at least partially coating theparticulates with a partitioning agent.
 10. A method of treating asubterranean formation comprising: providing a treatment fluidcomprising particulates at least partially coated with a polymer,wherein the polymer is deposited on the particulates by at leastpartially coating the particulates with a polymer solution comprisingthe polymer and a polar, aprotic solvent and then exposing theparticulates to an aqueous medium such that the solvent substantiallydissociates from the polymer solution and such that the polymersubstantially remains on the particulates; introducing the treatmentfluid into a portion of a subterranean formation; and, depositing atleast a portion of the particulates in the portion of the subterraneanformation.
 11. The method of claim 10 wherein the treatment fluidcomprises an aqueous liquid and a gelling agent.
 12. The method of claim10 wherein the polymer comprises at least one polymer selected from thegroup consisting of: polyacrylonitrile, a copolymer of acrylonitrile andmethyl acrylate, a copolymer of acrylonitrile and methyl methacrylate, acopolymer of acrylonitrile and vinyl chloride, a copolymer ofacrylonitrile and styrene, a copolymer of acrylonitrile and butadiene, apolyacylate, a polymethacrylate, a poly(vinyl alcohol), and a derivativeof poly(vinyl alcohol).
 13. The method of claim 10 wherein the polar,aprotic solvent comprises propylene carbonate.
 14. The method of claim13 wherein the solvent comprises at least one solvent selected from thegroup consisting of: N,N-dimethylformamide; acetone; tetrahydrofuran;1,4-dioxane; dimethylsulfoxide; tetramethylenesulfone; acetonitrile;hexamethyiphosphoramide;1,3-methyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone; propylene carbonate;and ethylene carbonate.
 15. The method of claim 10 wherein the polymeris present in the polymer solution in an amount of from about 5% toabout 95% by weight of the polymer solution.
 16. The method of claim 10wherein the particulates are coated with the polymer in an amount offrom about 0.1% to about 25% by weight of the particulates.
 17. A methodof creating a propped fracture in a portion of a subterranean formationcomprising: hydraulically fracturing a portion of a subterraneanformation to create or enhance at lease one fracture therein; providinga fracturing fluid comprising particulates at least partially coatedwith a polymer, wherein the polymer is deposited on the particulates byat least partially coating the particulates with a polymer solutioncomprising the polymer and a solvent and then exposing the particulatesto an aqueous medium such that the solvent substantially dissociatesfrom the polymer solution and such that the polymer substantiallyremains on the particulates; placing the fracturing fluid into the atleast one fracture; and, depositing at least a portion of theparticulates in the at least one fracture.
 18. The method of claim 1wherein the particulates comprise at least one particulate materialselected from the group consisting of: sand; bauxite; a ceramicmaterial; a glass material; a polymer material; apolytetrafluoroethylene material; a nut shell piece; a seed shell piece;a cured resinous particulate comprising a nut shell piece; a curedresinous particulate comprising a seed shell piece; a fruit pit piece; acured resinous particulate comprising a fruit pit piece; and wood.